1. Technical Field
The present disclosure relates in general to systems and methods useful in the production of energy. In particular, the present disclosure relates to systems and methods for production of energy from geothermal sources, as well as computer readable media for evaluating and/or comparing and/or simulating such systems and methods. The systems, methods, and computer readable media disclosed herein are useful in, for example, but not limited to, hydrocarbon exploration wells, production wells, well drilling, well completions, and well intervention.
2. Background Art
The thermal energy in co-produced oil and gas wells has been mentioned as a substantial resource for geothermal energy. In an assessment of geothermal energy by Tester, et. al., “The Future of Geothermal Energy”, Massachusetts Institute of Technology, (2006), the geothermal energy potential from co-production in seven United States Gulf Coast states is suggested to be as much as 5,300 megaWatts (MW). Another recent analysis by Petty et al., “Updated U.S. Geothermal Supply Characterization”, presented a the 32nd Workshop on Geothermal Reservoir Engineering, Stanford, Calif., Jan. 22-24, 2007 estimated a competitive coproduction resource for the United States at about 40 GW of power generation potential.
Candidate wells for co-produced energy may be oil and gas producers with high water cut, and the geothermal potential may be dependent upon two key parameters—rate of fluid production and resource temperature (for a given surface system and ambient temperature). In typical hydrocarbon wells, resource temperature requirements may impose minimum depth and geothermal gradient constraints. For instance, the geological thermal gradient along Texas Gulf Coast region (American Association of Petroleum Geologists, 1972) indicates that to reach geothermal temperatures of 250° F. (121° C.), the well has to reach depths of at least 12,000 ft. (3660 meters). Several maps of the US geothermal resource potential (based on temperature) have been developed (see, for example, Tester, et. al. 2006; USDOE). Recently, Augustine et al., “National Co-Produced Fluids Resource Estimate”, National Renewable Energy Laboratory (NREL) (2010) have presented a database of existing oil and gas wells and a method to assess their potential for thermal energy recovery. They propose this as an approach for screening co-production prospects in the United States.
Whether geo-pressured or depleted high water-cut wells, the most commonly suggested surface system for co-produced geothermal power generation is a binary cycle. Binary cycle power plants operate at inlet fluid temperatures of about 225°-360° F. (107°-182° C.) (Erkan, et al., “Understanding the Chena Hot Springs, Alaska, geothermal system using temperature and pressure data”, Geothermics 37 (6): 565-585 (2008)). In the typical binary power plant, hot water from a geothermal resource is brought to surface and is used to boil a working fluid, usually an organic compound with a low boiling point, such as isobutane, R245Fa, Ammonia, and the like. The working fluid is vaporized in a heat exchanger using the hot water, and drives a turbine to generate power. The working fluid is then cooled (condensed) and cycled back.
Sanyal, et al., “Geothermal Power Capacity from Petroleum Wells—Some Case Histories Of Assessment”, Proceedings World Geothermal Congress 2010, Bali, Indonesia, April (2010), conducted a study to assess power generation potential for co-produced petroleum wells. They present a correlation between the net power generated (per unit water flow rate) and the water temperature. The correlation is based on data from fifteen operating binary power plants, representing four different binary technologies.
Reservoir deliverability is the primary factor that drives the economic viability of any hydrocarbon or geothermal well production system. Oil and gas wells are designed to exclude as much water as possible. However, for fluid reservoirs with sufficient thermal energy potential, there will be a thermal energy price point at which thermal energy will (and should) influence the well design. Currently the majority of thermal energy from oil and gas production is wasted to the atmosphere. Unlike classical hydrothermal or even enhanced geothermal resources, co-produced oil and gas wells present more complicated economic considerations, given that economic value derives from both the hydrocarbons and heat energy recovered using a binary cycle at the surface. A few of the factors to consider in assessing economic potential for such a co-produced system include:                Tolerance to decline in pressure and rate: all oil and gas wells are subject to decline in pressure and production rate. Co-production systems must tolerate this decline to be viable.        Heat loss in wellbore as production rates decline: oil and gas wells typically flow at much lower rates than is typical in hydrothermal geothermal wells. Thus, the produced fluids are subject to significant heat loss in the wellbore, which worsens with decline in production rates.        The composition and pressure of hydrocarbons being produced: as mentioned earlier, most oil and gas wells are designed with the intent of minimizing produced water rates, whereas geothermal energy, at least with binary cycles, will depend upon increased water rate. Indeed, even the ability handle hot, high pressure, hydrocarbon-rich, produced fluids is probably beyond the current state-of-the-art in binary technology.        Ability to handle corrosive and sour fluids: in many situations where thermal potential exists, the produced fluids contain H2S, CO2 and other components that need to be handled through suitable selection of metallurgy in the binary plant heat exchanger. This will add cost to the surface system.        The loss of thermal energy if pre-exchange separation is required: if the binary plant cannot handle corrosive and sour produced fluids, separation may be required prior to entry into the plant. This implies a (hopefully small) loss in thermal energy available in the plant.        Design of wells and completions to optimize overall energy recovery: ultimately, as co-production becomes more attractive, well design will have to evolve to consider overall energy recovery rather than either hydrocarbon or geothermal energy recovery. This is bound to influence the overall well design, and hence the cost of well construction and operation.        
Introducing thermal energy recovery as an additional design criterion complicates the well design and production decisions. There is no simple set of formulas to determine the best solution when considering thermal energy recovery for a hydrocarbon recovery system. The thermal decline and hydrocarbon production decline curves from any well system will likely be different. The type of reservoir and hydrocarbon field development plan can also have a significant effect on the thermal energy recovery potential, since improved hydrocarbon recovery does not always imply improved thermal recovery. Evaluating the appropriate design and the associated economics for well systems that involve the co-production of hydrocarbons and thermal energy is thus a complex problem. Each resource, field development plan and production situation will need to be evaluated to decide whether a thermal recovery system is economically beneficial. In some cases maximizing the hydrocarbon production rate may not be the best way to optimize the overall energy recovery. Clearly, the story of co-production is an evolving one, with which the technical and economic evaluations will also evolve.
FIG. 1 illustrates a classical, prior art co-production system embodiment 100 based on a production well 20 at surface 18, wherein production well 20 comprises a casing 22, a production tubing 24, a production liner 25, a production packer 26, and packer fluid 32. Geothermal energy recovery in classical, prior art co-production system embodiment 100 is based on a binary surface heat exchange unit 6. A reservoir fluid, hydrocarbon/water mixture 21, is used as the hot fluid in a binary cycle at surface to generate geothermal energy. In one version, “a”, stream 21 flows directly to heat exchange unit 6. If the composition of reservoir fluid 21 is not favorable, a separator 4 may be needed upstream of the working fluid loop 12 to separate hydrocarbons (stream A) from produced water (stream B), which can result in loss of some of the thermal energy (this is shown as configuration “b” in FIG. 1). The recoverable thermal energy may be used to generate electric power in a power generation unit 8, for example using a turbine 10, or to drive a pump (not illustrated) that allows for greater production rates (and hence more hydrocarbon generation). De-energized working fluid, stream 5, is routed to a cooling facility 14, such as a cooling tower, and waste heat may be vented to atmosphere. Cooled, de-energized working fluid 7 is routed to heat exchange unit 6 to be re-heated by produced fluid. An energized working fluid stream 9 is routed to power generation unit 8. Produced fluids are routed to a facility 16 for further processing after giving up heat to the working fluid in heat exchange unit 6.
Although binary systems are fairly common in hydrothermal and enhanced geothermal system (EGS) projects, there are a few disadvantages when used in co-produced projects. The main limitations when a binary cycle is used in a co-produced well are:                production has to (usually) be dominated by water;        non-sour, non-corrosive composition is desired, given equipment limitations; and        production rate has to be very high to reduce wellbore heat loss and increase the net power generated.        
While use of co-production systems and methods of installation have increased, there remains a need for improved co-production systems and methods.